This disclosure relates generally to processes sour gas treating for H2S Removal, separation of impurities such as hydrocarbons, BTEX and mercaptans and the Acid Gas Enrichment integrated system from the sour gas field developments, refineries, associated gas, shale gas, SYN GAS from power plants, natural gas processing applications, and early production facility more particularly to processes the mixture of the 100% lean H2S gas stream with impurities such as heavy hydrocarbons, mercaptans, benzene, toluene and Xylene (BTEX). The combination of innovation schemes comprises the H2S Removal and the Acid Gas Enrichment and separation of hydrocarbons from H2S to promote a cost effective options by reducing the number of units in an efficient manner and to achieve near 100% sulfur recovery with significant cost and energy saving. The separated hydrocarbon stream gas is sent to the first zone of the reaction furnace in the sulfur recovery where operates at a higher temperature to destruct the impurities or is sent to the quench system in the tail gas unit. The rich H2S acid gas is sent to the first or second zone of the reaction furnace in the sulfur recovery unit depending on the combustion temperature. With further aspects of the present invention, the innovation scheme is a combination of the main absorber(s) and the primary and the secondary regeneration unit. In summary, by adding the secondary regenerator to the acid gas removal unit with the unique scheme, a separate acid gas enrichment unit and a separate hydrocarbons removal unit could be eliminated and the H2S removal, hydrocarbons removal and acid gas enrichment is integrated in this unique invention. The tail gas absorber can operate as the H2S Enrichment Absorber and can operate at the higher H2S rich loading compare to typical tail gas absorber which ultimately lower amine solvent circulation can be used.